NO172590B - BROWN HOLE FLUID AND USE OF THIS FOR AA REDUCE THE PERMEABILITY OF A BACKGROUND FORM THAT REPLACES A DRILL HOLE - Google Patents

Abstract

This invention relates to a composition and method of temporarily reducing the permeability of subterranean formations penetrated by a wellbore. In particular, it relates to an inexpensive, low molecular weight condensation product of hydroxy acetic acid with itself or compounds containing other hydroxy-, carboxylic-acid-, or hydroxycarboxylic-acid moieties and method for preventing fluid loss during well treatment.

Description

This invention relates to a wellbore fluid and its use to reduce the permeability of a subsurface formation penetrated by a borehole.

At various times during the lifetime of a well formed in an underground formation for the production of oil and gas, it is desirable to treat the well. Such treatments include perforation, gravel packing, fracturing and etching. To carry out these treatments, fluid loss regulating agents and diverting agents are used, which in this description are referred to as treatment agents.

Although high fluid permeability is an important property of a hydrocarbon-yielding formation, high permeability will have an adverse effect on various treatments. Under e.g. a fracturing treatment, it is desirable to limit the loss of treatment fluid to the formation in order to maintain a cleavage effect and cause propagation of the fracture. Therefore, the effective performance of certain treatments of the wellbore requires a temporary reduction of the permeability of certain formation layers to reduce the loss of treatment fluid during the treatment. Several agents to prevent fluid loss and diversion agents have been developed for use in certain treatments, but many of them leave a residue in the wellbore or in the formation layers after the treatment is completed. This residue can cause permanent deterioration of the production capacity of the formation. Examples of materials that have been used to reduce permeability include naturally occurring materials such as crushed limestone, rock salt, oyster shell and silica flour. These relatively inert materials form a filter cake that can remain on the formation surface and cause an unwanted, permanent reseal. Other materials, such as salt, benzoic acid and naphthalenes, have some water or oil solubility, or they may be sublimable. These materials cause disadvantages, as it is often difficult to determine the well's surroundings. Still other types of materials are oil-soluble, water-insoluble materials, such as soaps, gels, wax materials and resin polymers. These materials are intended to be removed using hydrocarbon liquids from the subsoil. However, there is no guarantee that there will be any contact with oil in microscopic rock pores, and thus there is a possibility that these materials will not be dissolved and that permanent damage to the formation may occur.

Polyester polymers of hydroxyacetic acid with lactic acid have been proposed as oil spill treatment agents. These polymers were extensively investigated in the 1950s as possible textile fibers, until it was found that they easily hydrolyzed when exposed to heat and moisture. The polyester polymers are stated to be substantially insoluble in the wellbore fluid, but they degrade in the presence of water at elevated temperatures within about 1 to 7 days to form oligomers that are at least partially soluble in the formation fluid and are easily removed from the well when it is in production. These polyester polymers are expensive to produce, and they have limited effectiveness at low temperatures. There remains a need for an inexpensive agent for preventing fluid loss and for diversion purposes, which has hydrolytic properties that enable its use in oil wells with a wide range of ambient temperatures. This treatment agent must initially be insoluble in the wellbore fluid, and it must remain insoluble long enough for the treatment to be carried out, and it must break down quickly as soon as the treatment is completed, so that the well can quickly be brought back into production. The treatment agent must also have sufficiently high crystallinity and a sufficiently high melting point to enable painting to the desired particle size and to prevent melting or softening during painting or during use. Preferably, the treatment agent must be capable of being adapted to temperature conditions and the desired timing during an oil well treatment. This means that the decomposition time at a given temperature must be adaptable. The present invention meets these requirements.

The invention thus provides a wellbore fluid to reduce the permeability of a subsurface formation penetrated by a wellbore, containing dispersed solid particles of a condensation product based on hydroxyacetic acid, which condensation product has a melting point of at least 65.6° C and is sufficiently high to avoid softening or melting during use, is essentially insoluble in the wellbore fluid and is degradable in the presence of water at elevated temperature into monomers and dimers which are at least partially soluble in oil or water. The new wellbore fluid is characteristic in that the condensation product is a condensation product of hydroxyacetic acid with up to 15% by weight of cocondensing compounds containing other hydroxy, carboxylic acid or hydroxycarboxylic acid groups and has a number average molecular weight of 200-4000 and is essentially crystalline both at the ambient temperature and at the relevant wellbore temperatures.

The condensation product based on hydroxyacetic acid which is used in the method is preferably made up of oligomers with a number average molecular weight of from 200 to 650. They are primarily from trimers and up to decamers. They are soluble in both aqueous media and hydrocarbon media, but will break down at given rates when exposed to moisture and temperatures above 48.9°C, forming soluble monomers and dimers. The rate of hydrolysis at a given temperature can be increased by incorporating small amounts of other molecules (usually less than 15% by weight) in the reaction environment where the hydroxyacetic acid is condensed. These materials are usually made up of flexible or more voluminous molecules which partially prevent crystallinity, but which do not prevent the condensation product from becoming easily crumbly. Thus, the treatment agent can be "tailored" so that the hydrolysis rate can be set from a few hours to several days, by regulating the amount and nature of crystallinity.

The wellbore fluid according to the invention contains dispersed an agent to prevent fluid loss or to cause drainage, which agent as mentioned comprises low-molecular condensation products of (1) hydroxyacetic acid or of (2) hydroxyacetic acid which is co-condensed with up to 15% by weight of compounds containing other hydroxy- , carboxylic acid or hydroxycarboxylic acid groups, or combinations or mixtures thereof. The compounds containing these groups, and with which the hydroxyacetic acid is cocondensed, are referred to here as modifying molecules. These modifying molecules include acetic acid, tribasic acids such as citric acid, dibasic acids such as adipic acid, diols such as ethylene glycol, and polyols. They also include bifunctional molecules such as 2,2-(bishydroxymethyl)-propanoic acid. By cocondensing hydroxyacetic acid with different modifying molecules, varied physical and hydrolytic properties are obtained, which makes it possible to "tailor" the treatment agent to the oil well temperatures and the necessary timing in connection with the treatment. Compatible plasticizers can also be used to modify the crystalline character, but they have proven to be less effective than the above-mentioned cocondensation molecules. Preferred modifying molecules are lactic acid, citric acid, 2,2-(bishydroxymethyl)propanoic acid, trimethylolethane and adipic acid. The most preferred are lactic acid and citric acid. As mentioned, the condensation product has a number average molecular weight of from 200 to 4000. Preferably, the condensation product is an oligomer with a number average molecular weight of from 200 to 650, and it comprises primarily from trimers up to decamers.

The treatment agent must be sufficiently hard or easily crumbly so that it can be ground to a small particle size, and it must have a sufficiently high melting point to avoid softening and deformation during use and during painting. The percentages of hydroxyacetic acid and cocondensation compounds can be regulated so that a sufficient crystallinity and a sufficiently high melting point or softening point is achieved. The melting point must be higher than 65.6°C. The condensation time and temperature can also be varied.

The condensation and cocondensation products used in the wellbore fluid according to the invention are produced according to methods well known in the art. The hydroxyacetic acid can be heated alone or together with the cocondensation molecules mentioned above, in the presence of a catalyst such as antimony trioxide. The condensation is preferably carried out in an inert atmosphere and at a vacuum of 30-60 mm. By varying the percentages of hydroxyacetic acid and co-condensation compounds and likewise the condensation temperatures and time, it becomes possible to "tailor" the condensation product so that it breaks down at different rates for given wellbore temperatures. Different condensation and cocondensation products can be physically mixed with each other or fused together to achieve an even wider range of degradation rates.

The wellbore fluid can consist of water, oil, xylene, toluene, salt solutions, water-in-oil emulsions or oil-in-water emulsions. The amount of treatment agent required for satisfactory fluid control will vary greatly, depending on the size of the formation, the degree of permeability of the formation, the size of the particles of the treatment agent and on other variables, such as the viscosity of the wellbore fluid and the volumetric fluid losses that can be allowed. However, it is assumed that for a treatment agent with a particle size in the range from 0.1 to 1500 µm, an amount of treatment agent of from 38 to 380 g/m<3> wellbore water will be sufficient for most applications.

The invention also contemplates an application of the new wellbore fluid to reduce the permeability of an underground formation penetrated by a wellbore.

In order to be able to use the wellbore fluid according to the invention, one must first determine the temperature of the well. A treatment agent is selected which is adapted to this temperature, and this is mixed with the wellbore fluid in the appropriate proportion. For well temperatures above 93.3°C, condensation products of only hydroxyacetic acid can be used. For temperatures below 93.3°C, the crystallinity should be partially broken through cocondensation of hydroxyacetic acid with modifying molecules as described above. When the wellbore fluid is injected into the formation, the treatment agent contained in the fluid will ensure that the penetration of the treatment fluid into the formation is as small as possible. After completion of treatment, the well may be allowed to warm back to its ambient temperature. At this temperature, the treatment agent, in the presence of local water, will break down into soluble or partially soluble monomers and dimers within a few hours to a few days. These at least partially soluble monomers and dimers can be easily removed from the well during the production phase.

The following examples illustrate the invention.

examples 1-8 indicate methods for producing condensation and cocondensation products of hydroxyacetic acid which are suitable for use according to the invention. Examples IA and 6A show the effect of post-heating of the condensation products from example 1 and example 6 respectively. All percentage amounts are calculated on a weight basis.

The number average molecular weight of the condensation or cocondensation product in each example was determined by the following method:

Method for determining molecular weight.

About. 0.3 g of condensation product is dissolved in 60 ml of dimethyl sulphoxide, and the solution is titrated to pH 8.0 with 0.1 N sodium hydroxide. The number-average molecular weight is determined using the following formula: molecular weight = g material/ml 0.1 N NaOH x 10,000. As a result of the extreme insolubility of these condensation products, small amounts of undissolved materials will give higher number average molecular weights by this method than the real values.

The weight percent hydrolysis for each condensation or cocondensation product listed in Tables I, II and III was determined by the following method:

Method for determining % hydrolysis.

About. Ig of condensation product is added to 100 ml of 2% potassium chloride solution (KC1), and the mixture is kept at a regulated temperature for varying periods of time. Aliquots of 10 ml are then taken out, and these are added to 60 ml of dimethylformamide. This solution is titrated to neutral pH with 0.1 N sodium hydroxide. The amount of hydrolysis in weight percent is calculated using the following formula: % hydrolysis = ml 0.1 N NaOH/g sample x 6.25. The value 6.25 corresponds to a hydroxyacetic acid tetramer with an equivalent average molecular weight of 62.5 per unit.

Examples

Example 1. 100% hydroxyacetic acid (HAA).

A mixture of 181.4 kg (net) 70% HAA and 18 g of antimony trioxide was heated under nitrogen to 170°C while removing water, at which time a vacuum of 30-60 ml was applied and the temperature was increased to 200°C with continued removal of condensation water. The reaction bluing was held for approx. 6 hours at 200-220°C and then removed and allowed to cool to a crystalline solid of melting point 206°C. 94.3 kg of product was obtained. The number average molecular weight was 606.

Example IA. Post-heating of the product from example 1.

A sample of the product from Example 1 was heated in a vacuum oven at 150°C for 24 hours at a vacuum of 30-60 ml Hg. The melting point increased to 210-211°C, and the number average molecular weight increased to 4019.

Example 2. 8% lactic acid/ 92% hydroxyacetic acid (LA/ HAA).

170.6 kg (net) of 70% HAA, 11.8 kg (net) of 88% LA and 18 g of antimony trioxide were heated under nitrogen and prepared in the same manner as described in Example 1. A total amount was obtained crystalline product of 95.7 kg. Melting point 185°C. The number average molecular weight was 226. After extraction of soluble monomer and dimer from the condensation product, the number average molecular weight was 303.

Example 3. 8% lactic acid/ 92% hydroxyacetic acid (LA/ HAA).

A mixture of 170.6 kg (net) 70% HAA, 11.8 kg (net) 88% lactic acid and 18 g antimony trioxide was heated under nitrogen to 167°C while removing water, at which point a vacuum of 30-60 mm Hg was applied and the temperature was increased to 117°C with continued removal of water of condensation. The reaction mixture was held for 3 hours at 170-180°C and was then taken out and allowed to cool, yielding a crystalline solid of melting point 172-173°C. The product was obtained in an amount of 98.0 g. The number average molecular weight was 193.

Example 4. 8% lactic acid/ 92% hydroxyacetic acid (LA/ HAA).

A mixture of 170.6 kg (net) 70% HAA, 11.8 kg (net) 88% lactic acid and 18 g antimony trioxide was heated under nitrogen to 167°C while removing water, at which point applied a vacuum of 30-60 mm and the temperature was increased to 170°C while still removing condensation water. The reaction mixture was held for 2.75 hours at 170-174°C and then removed and allowed to cool. A crystalline solid with a melting point of approx. 160-162°C. The weight of the product was 98.4 kg. The number average molecular weight was 151. The product was too soft to be ground without the use of dry ice.

Both the degree of condensation and the percentage amount of co-condensed molecules have an impact on the rate of hydrolysis. Table I shows the effect achieved when moving from condensation products based on 100% HAA to condensation products containing 8% LA and 92% HAA and the effects achieved by condensation of 8% LA/92% HAA for a shorter time and/or at lower temperatures .

From the table, it will be seen that the addition of lactic acid to hydroxyacetic acid increased the rate of hydrolysis. Carrying out the condensation at 180°C (Example 3) instead of at 220°C (Example 2) resulted in faster hydrolysis and lower number average molecular weight, and this was also achieved with the slight reduction of the cycle time at 180°C that was made in Example 4 , compared to example 3. In example 4, however, the reduction in the number average molecular weight was sufficiently large to prevent the product from being ground without the use of dry ice.

Although the lowest number average molecular weight gave the greatest hydrolysis rates, further increases were still desirable. Improvements were achieved through the incorporation of even more bulky molecules than lactic acid in the HAA condensation. Tables II and III show the effects of adding these molecules.

Example 5. 7% citric acid/ 93% hydroxyacetic acid (CA/ HAA).

A mixture of 1630 g (net) 70% HAA, 252 g CA and 0.169 g antimony trioxide was heated under nitrogen to 150°C while removing water, at which time a vacuum of 30-60 mm Hg was applied and the heating continued to exist

180°C. After 7.5 hours at 180-190°C, the mixture was taken out and allowed to cool. A product with a melting point of 170-171°C was obtained. The number average molecular weight was 177.

Example 6. 4% citric acid/ 3% lactic acid/ 2% 2, 2-(bishydroxy-methyl)-propanoic acid/ 91% hydroxyacetic acid

( CA/ LA/ BHMPA/ HAA).

A mixture of 1646 g (net) 70% HAA, 126 g CA, 54 g (net) 88% LA, 40 g BHMPA and 0.169 g antimony trioxide was heated under nitrogen to 150°C while removing water, on at which point a vacuum of 30-60 mm Hg was applied and heating was continued to 180°C. After 7 hours at 180°C, the mixture was taken out and allowed to cool. A product with a melting point of 166-168°C was obtained. The number average molecular weight was 208.

Example 6A. Post-heating of the product from example 6.

Material from Example 6 was heated at 120°C under a 635 mm vacuum for 65 hours (over the weekend) to achieve cross-linking and higher molecular weight. The melting point rose to 172-174°C, and a number average molecular weight of 608 was obtained after extraction of 2% by weight of unreacted monomer and soluble dimer.

Example 7. 5% adipic acid/ 4% ethylene glycol/ 1% trimethylol-ethane/ 90% hydroxyacetic acid ( AA/ EG/ TME/ HAA).

A mixture of 1600 g (net) 70% HAA, 108 g AA, 41 g EG, 12.3 g TME and 0.169 g antimony trioxide was heated under nitrogen to 150°C while removing water, at which point it was pressurized a vacuum of 30-60 mm Hg and heating was continued to 180°C. After 6.5 hours at 180°C, the mixture was taken out and allowed to cool. A product with a melting point of 165°C was obtained. The number average molecular weight was 301.

Example 8. 4% citric acid/ 4% lactic acid/ 92% hydroxyacetic acid

(CA/LA/HAA).

A mixture of 1646 g (net) 70% HAA, 140 g CA, 68 g (net) 88% LA and 0.169 g antimony trioxide was heated under nitrogen to 150°C while removing water, at which point applied a vacuum of 30-60 mm Hg and heating was continued to 180°C. After 6 hours at 180°C, the mixture was taken out and allowed to cool. A product with a melting point of 172-173°C was obtained. The number average molecular weight was 193.

The values listed in Tables I, II and III for weight percent hydrolysis are based on an assumed molecular weight for the condensation products of 62.5 per condensed unit. As the value 62.5 is only an approximation, the value for weight percent hydrolysis is also an approximation of the ability of the condensation product to reseal/unreseal. A more rigorous one

method for measuring the amount of condensation product that is

been solubilized at a given temperature during a given time is the isolation technique described below. This technique does not require the assumption of a molecular weight, and it also shows the amount of unreacted monomer and soluble dimer present in the condensation product. The unreacted monomer and the soluble dimer will be ineffective with regard to resealing, and they should therefore not be taken into account when determining the treatment agent's ability to reseal/remove resealing. Reference is made to tables IV, V and VI.

Method for determining % solubility by isolation.

About. Ig condensation product is added to 25 ml of 2% by weight KC1 solution or 15% by weight HC1, and the mixture is kept at a regulated temperature for periods of varying length. The cooled mixture is then filtered, and the isolated solid is washed with 10 ml of water and then dried. The solid (together with tared filter paper) is dried in a vacuum at 65-70°C. The amount of undissolved material is compared to the original weight.

Tables IV, V and VI show the result of post-heating, which increases the number average molecular weight. The data after 1 hour at room temperature gives an indication of the unreacted monomer and the soluble dimer, which will have no resealing effect. A significant reduction takes place after post-heating. The other data show that the reheated material dissolves more slowly at a given temperature, both in a 2% KCl solution and in 15% HC1.

Claims (5)

1. Wellbore fluid for reducing the permeability of a subsurface formation penetrated by a wellbore, containing dispersed solid particles of a condensation product based on hydroxyacetic acid, which condensation product has a melting point of at least 65.6°C and is sufficiently high to avoid softening or melting during use, is essentially insoluble in the wellbore fluid and is degradable in the presence of water at elevated temperature into monomers and dimers which are at least partially soluble in oil or water, characterized in that the condensation product is a condensation product of hydroxyacetic acid with up to 15% by weight of cocondensing compounds containing other hydroxy, carboxylic acid or hydroxycarboxylic acid groups and has a number average molecular weight of 200-4000 and is essentially crystalline both at the ambient temperature and at the relevant wellbore temperatures. 2. Wellbore fluid according to claim 1, characterized in that the condensation product is an oligomer with a number average molecular weight of 200-650. 3. Wellbore fluid according to claim 2, characterized in that the condensation product comprises from trimers up to decamers. 4. Wellbore fluid according to claim 1, characterized in that the co-condensing compounds are lactic acid, citric acid, adipic acid, trimethylolethane or 2,2-(bishydroxymethyl)-propanoic acid, preferably lactic acid or citric acid. 5. Use of a wellbore fluid according to claims 1-4 to reduce the permeability of an underground formation that is penetrated by a wellbore.